System and method for fracturing a hydrocarbon producing formation

ABSTRACT

A system and method for fracturing a hydrocarbon producing formation in which a fracturing tool is inserted in a wellbore adjacent the formation, and fracturing fluid is introduced into the annulus between the fracturing tool and the wellbore and flows to the formation.

BACKGROUND

This invention relates to a system and method for fracturing a hydrocarbon-producing formation with a fracturing system located in a wellbore adjacent the formation.

Hydraulic fracturing is often utilized to stimulate the production of hydrocarbons from subterranean formations penetrated by wellbores. Such hydraulic fracturing treatments typically include perforating the well casing adjacent the formation and introducing a fracturing fluid through tubing into a tool assembly in the casing, and to a ported sub, or the like, connected in the tool assembly. The fluid discharges from the ported sub at a relatively high pressure and passes through the perforations in the well casing and into the formation to fracture it and promote the production of the hydrocarbons such as oil and/or gas. Where only one portion of a formation is to be fractured as a separate stage, it is isolated from the other perforated portions of the formation using conventional packers or the like, and a fracturing fluid is pumped into the wellbore through the perforations in the well casing and into the isolated portion of the formation to be stimulated at a rate and pressure such that fractures are formed and extended in the formation. Propping agent may be suspended in the fracturing fluid which is deposited in the fractures. The propping agent functions to prevent the fractures from closing, thereby providing conductive channels in the formation through which produced fluids can readily flow to the wellbore. In certain formations, this process is repeated in order to thoroughly populate multiple formation zones or the entire formation with fractures.

In situations where casing is not present, it is sometimes desirable to use the above approach to create a preferential center of fracture point. In general, this center of fracture point coincides with the center of the tubing or casing. Such a method is described in U.S. Pat. No. 5,765,642, where a jetting tool is used to place such fractures, with or without the use of isolation methods.

However, these types of techniques are not without problems. For example, it is typically not possible with traditional fracturing technology to direct the fracture in a specific direction, as fractures are controlled primarily by the mechanics of the formation and the wellbore. In traditional fracturing methods, the center of the fracture is in the center of the tubing or casing. This may result in fracturing into water-producing formations or fracturing into another known undesirable fracture or well. Such methods may also result in fracturing in the direction of least principle stress creating near-wellbore-toruosity during the fracture treatment and possible formation sand flowback problems.

Also, with traditional methods of well fracture it is typically not possible to determine the exact location and orientation of the ported sub, and hence, the exact location of the fractures to be formed. Further, traditional hydraulic fracturing tools most often lack critical equipment necessary to complete other procedures in the wellbore, such as packing, orientation and the like. These traditional hydraulic fracturing tools must most often be removed from the wellbore and other tools inserted for such additional procedures, resulting in additional time and costs. Therefore, what is needed is a fracturing system and method that eliminates the above problems.

SUMMARY

The present invention is directed to an apparatus and method for fracturing and/or perforating a formation.

More specifically, one embodiment of the present invention is directed to a method of fracturing a subterranean formation penetrated by a wellbore by positioning a fracturing tool within the wellbore, with the fracturing tool having a fracturing tool outer wall. A fracture is initiated with the center of fracture point located within the subterranean formation but not within the wellbore. A fracture is then created.

Another embodiment of the present invention is directed to a method of fracturing a subterranean formation penetrated by a wellbore by positioning a hydrajetting tool assembly within the wellbore. The hydrajetting tool assembly has a hydrajetting sub capable of being inserted into a wellbore. The hydrajetting tool assembly includes a hydrajetting sub defined by an outer wall and an inner fluid flow passageway, and a port formed through the outer wall and adapted to communicate with the inner fluid flow passageway, a nozzle mounted within the port, and a directional sub, wherein the directional sub is mechanically connected to the hydrajetting sub. A fracture is initiated, wherein the center of fracture point is located within the subterranean formation but not within the wellbore by introducing a fracturing fluid into the inner fluid flow passageway of the hydrajetting sub and jetting the fracturing fluid through the nozzle against the subterranean formation at a pressure sufficient to form cavities in the formation, wherein the cavities in the formation are in fluid communication with the wellbore. A fracture is created by maintaining the fracturing fluid in the cavities while jetting at a sufficient static pressure to fracture the subterranean formation.

Still another embodiment of the present invention is directed to a hydrajetting tool assembly mechanically connected to a work string, wherein the work string comprises an outer wall and an inner wall. The hydrajetting tool assembly is capable of being inserted into a wellbore and includes a hydrajetting sub defined by hydrajetting sub outer wall, an inner fluid flow passageway, and a port formed through the outer wall adopted to communicate with the inner fluid flow passageway. The hydrajetting tool assembly further includes a nozzle mounted within the port and a directional tool mechanically connected to the hydrajetting sub.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present disclosure and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings:

FIG. 1 is an overview of subterranean formation fractured using a traditional fracturing tool in a mostly vertical section of a wellbore.

FIG. 1 a is an overview of a subterranean formation fractured using a fracturing tool of the present invention in a mostly vertical section of a wellbore.

FIG. 1 b is an overview of a subterranean formation fractured using a fracturing tool of the present invention in a mostly horizontal section of a wellbore.

FIG. 1 c is an overview of a subterranean formation fractured using a fracturing tool of the present invention in a mostly vertical section of a wellbore

FIG. 2 is an elevational view of one embodiment of a hydrajetting tool assembly according to the present invention.

FIG. 3 is a cutaway view of an embodiment of a hydrajetting tool assembly according to the present invention.

FIG. 4 is a cutaway view of one embodiment of a check valve included in one embodiment of the hydrajetting tool assembly according to the present invention.

FIG. 5 is a schematic diagram of a subterranean formation depicting use of one embodiment of a hydrajetting tool assembly according to the present invention.

FIG. 6 is a schematic diagram of a subterranean formation fractured using one embodiment of a hydrajetting tool assembly according to the present invention

DETAILED DESCRIPTION

As described above, it is typically not possible with traditional fracturing technology to direct the fracture in a specific direction. Further, traditional fracturing methods typically have a center of fracture point in the center of the tubing or casing. FIG. 1 depicts one embodiment of a traditional fracturing operation. Traditional fracturing tool 1000 is shown located within wellbore 1100. Wellbore 1100 is located within formation 1150. Numerous embodiments of traditional fracturing tools 1000 exist. Traditional fracturing tool 1000 shown in FIG. 1 has nozzles 1010 located on opposite sides of traditional fracturing tool 1000. In other embodiments of traditional fracturing tool 1000, nozzles 1010 may be located in four positions located 90 degrees apart around the circumference of traditional fracturing tool 1000; in still other embodiments of traditional fracturing tool 1000, other configurations of nozzles may be placed around the circumference of traditional fracturing tool 1000, including, but not limited to, every 60 degrees or every 30 degrees. In yet still other embodiments of traditional fracturing tool 1000, nozzles may be replaced with ports or other methods of transferring fluids in the wellbore. Various embodiments of traditional fracturing tool 1000 typically have one primary characteristic in common, i.e., when fluid is introduced through into and through traditional fracturing tool 1000, such fluid exits about the circumference of traditional fracturing tool 1000. This multi-directional exit characteristic common to typical traditional fracturing tools 1000 forms fracture 1200 in formation 1150. Center of fracture point 1250 is therefore typically located within wellbore 1100 when using traditional fracturing tools 1000. In some embodiments of traditional fracturing tool 1000, a positioner is used to determine the orientation and/or location of traditional fracturing tool 1000.

A fracturing operation in a substantially vertical section of wellbore 1100 using a fracturing tool of the present invention is depicted in FIG. 1 a. Fracturing tool 2000 is shown having nozzles 2020 in approximately a unitary direction. While fracturing tool 2000 is shown having nozzles 2020, any traditional fracturing tool may be used in the present invention as long as the method of introducing fluid into wellbore 1100 is limited to approximately a unitary direction. When fluid is introduced through into and through fracturing tool 2000, such as through nozzles as shown in FIG. 1 a, the fluid exits fracturing tool 2000 in approximately a unitary direction. Hence, when formation 1150 is fractured, as shown in FIG. 1 a using one embodiment of the present invention, fracture 1200 has center of fracture point 1250 located away from wellbore 1100, i.e., not located within wellbore 1100.

FIG. 1 a further depicts directional tool 2100. Directional tool 2100 is mechanically connected to fracturing tool 2000. Directional tool 2100 may be any one of a number of devices suitable for determining both the inclination and azimuth angle of fracturing tool 2000. Suitable examples of directional tool 2100 include, but are not limited to, gyroscopic surveyors, wireline steerers, memory pulsed neutron logging devices, and electromagnetic logging devices. Note that directional tool 2100 may include those types of tools described below as types of directional sub 40. Through the use of the combination of directional tool 2100, the operator may determine the inclination and azimuth angle of fracturing tool 2000. The operator may then rotate fracturing tool 2000 to the appropriate predetermined position, either through the use of surface equipment or downhole equipment. Thus, the operator may, through the use of the combination of fracturing tool 2000 and directional tool 2100 to create center of fracture point 1250 at any location about wellbore 1100 as desired. FIG. 1 b depicts a substantially identical operation in a substantially horizontal section of wellbore 1100.

By orienting nozzles at an angle from fracturing tool wall 2030, as shown in FIG. 1 c, it is possible to orient the fracture at an angle from the wellbore. For instance, when in a mostly vertical section of the wellbore, in the embodiment shown in FIG. 1 c, nozzles 22 are at an acute angle to fracturing tool wall 2030. As further shown in FIG. 1 c, by orienting nozzles 22 at an acute angle to the fracturing tool wall 2030, center of fracture point 1250 is placed at an acute angle to the wellbore and the later-resultant fractures will propagate, at least in part, at an acute angle to the wellbore.

Referring now to FIG. 2, a fracturing tool for use in accordance with one embodiment of the present invention, a hydrajetting tool assembly, is illustrated and generally designated by the numeral 10. In discussion of the hydrajetting tool assembly 10, the terms “above” and “below” are used to denote positions of equipment associated with hydrajetting tool assembly 10. Such references are to positions of equipment in a vertical section of the wellbore, but are used only to denote position, not to limit hydrajetting tool assembly 10 to any particular wellbore section. The hydrajetting tool assembly 10 is shown connected to a work string 12 through which a fluid may be pumped at a high pressure. Work string 12 is typically jointed pipe or coiled tubing. In one embodiment of the present invention, work string 12 is capable of transmitting data to and from the surface via wireline communication, typically from hydrajetting tool assembly 10 to surface equipment. Where wireline communication is used, conducting material is installed between the outer and inner walls of work string 12. Typically, when utilizing conducting material, work string 12 should be composed of a composite material with limited ability to conduct electricity to avoid electrical shorts. The conducting material connects surface equipment with hydrajetting tool assembly 10, described below, to allow communication between surface equipment and hydrajetting tool assembly 10. Other non-limiting means of communication between hydrajetting tool assembly 10 and surface equipment include mud pulse or sonic communication means. Where mud pulse or sonic communication is used, mud pulse or sonic generators are generally affixed to hydrajetting tool assembly 10 and used to communicate between hydrajetting tool assembly 10 and surface equipment through drilling mud and work string 12, respectively.

Hydrajetting tool assembly 10 is comprised of at least hydrajetting sub 20 and directional sub 40. Referring to FIG. 3, hydrajetting sub 20 includes an inner fluid flow passageway 18 extending therethrough and communicating with at least one and preferably as many as feasible, angularly-spaced, lateral, ports 21 disposed through the sides of hydrajetting sub 20. A nozzle 22 is mounted within each of ports 21. As will be described further hereinbelow, nozzles 22 are preferably disposed in a single plane which is positioned at a predetermined orientation with respect to the longitudinal axis of hydrajetting sub 20. Such orientation of the plane of nozzles 22 typically coincides with the orientation of the plane of minimum principal stress in the formation to be fractured relative to the longitudinal axis of the wellbore penetrating the formation.

Ports 21 are generally approximately circular openings, although other shapes may be used depending on the particular design parameters. Ports 21 are designed to allow the mounting of nozzles 22 within ports 21. Nozzles 22 are designed to allow fluid flow from inner fluid flow passageway 18 through hydrajetting sub outer wall 24. Nozzles 22 are further designed to cause fluid impingement on formation 1150, as shown in FIG. 5. Nozzles 22 may extend beyond the surface of hydrajetting sub 20, as shown in FIG. 2, or nozzles 22 may terminate at the surface of hydrajetting sub 20. In an exemplary embodiment where nozzles 22 extend beyond the surface of hydrajetting sub 20, nozzles. 22 are approximately cylindrical, hollow projections that may be in a straight line orientation, but may more commonly be oriented at an angle between about 1° and about 90° from hydrajetting sub outer wall 24, often between about 30° and about 90°, with some embodiments between about 40° and about 90°. Nozzles 22 orientation and location are dependent upon the formation to be fractured. Nozzle 22 orientation may coincide with the orientation of the plane of minimum principal stress, or the plane perpendicular to the minimum stress direction in the formation to be fractured relative to the axial orientation of wellbore 1100 penetrating the formation. Nozzle 22 circumferential location about hydrajetting sub 20 should be chosen depending on the particular well, field or, formation to be fractured. For instance, in certain circumstances, it may be desirable to orient all nozzles 22 in one direction or at 180° stations about the circumference of hydrajetting sub 20 for other formations. As described above, when it is desirable to form a fracture initiation point outside the wellbore, nozzles 22 should be oriented in approximately a unitary direction. It is further possible to alter the internal diameter of nozzles 22 dependent upon operator need. One of ordinary skill in the art may vary these parameters to achieve the most effective treatment for the particular well.

In typical embodiments, nozzles 22 have a diameter sized so as to increase the pressure of the fluid being jetted through nozzles 22 to a suitable pressure to cause microfractures in formation 1150 or to perforate any wellbore casing that may be present. The increased pressure allowed by reducing the diameter of nozzles 22 increases the pressure drop of fluid traveling through nozzles 22. Nozzles 22 may be composed of any material that is capable of withstanding the stresses associated with fluid fracture of formation 1150 and the abrasive nature of the fracturing or other treatment fluid and any proppants or other fracturing agents used. Nonlimiting examples of an appropriate material of construction of nozzles 22 are tungsten carbide and certain ceramics.

Mechanically connected to hydrajetting sub 20 in one embodiment of the present invention is downhole power unit (DPU) 14. DPU 14 is a self-contained unit designed to provide electrical power to downhole equipment, such as the equipment described below. DPU 14 is most commonly a device containing a battery, a fuel cell or a fluid motor/generator combination. An acceptable device for use as DPU 14 is the Downhole Power Unit available from Halliburton Energy Services, Inc. In at least one embodiment of the present invention, DPU 14 is electrically connected to work string 12 so as to allow data transmission to DPU 14 through the conducting materials within the walls of work string 12. DPU 14 may be located above hydrajetting sub 20, as shown in FIG. 2 or below hydrajetting sub 20. Where DPU 14 is located above hydrajetting sub 20, it must be designed so as to allow fluid flow to inner fluid flow passageway 18. Where DPU 14 is located below hydrajetting sub 20, it may be designed to allow fluid flow to pass through it, or DPU 14 may also act as a plug such that no treatment fluids, for instance, the fracturing fluid, may exit through the open end of hydrajetting tool assembly 10. In another embodiment of the present invention, DPU 14 is absent and rotation may be provided from surface equipment, such as through conductive material located within the wall of work string 12.

Hydrajetting sub 20 is typically mechanically connected, either directly, as shown in FIG. 2, or indirectly, to rotating sleeve 16. Rotating sleeve 16 is designed to be rotated about its longitudinal axis and, by the connection between hydrajetting sub 20 and rotating sleeve 16, rotate hydrajetting sub 20 about its longitudinal axis. Hence, by changing the orientation of rotating sleeve 16 about its longitudinal axis, nozzles 22 may be rotated about the longitudinal axis of the wellbore. Rotation of rotating sleeve 16 may be achieved by a mechanical connection to DPU 14, or by surface equipment. In another embodiment of the present invention, rotating sleeve 16 may be omitted and hydrajetting sub 20 may be oriented by means of surface equipment.

In particular embodiments of the present invention, hydrajetting sub 20 may be mechanically connected to check valve 200. Check valve 200, as shown in FIG. 4, is in some embodiments of the present invention, a tubular, ball activated, check valve that is connected to the end of the hydrajetting sub 20 opposite from the work string 12. Check valve 200 includes a longitudinal flow passageway 202 extending therethrough, which in the embodiment shown in FIG. 4, connects with inner fluid flow passageway 18. Longitudinal passageway 202 typically includes reduced diameter longitudinal bore 204 through the exterior end portion of the check valve 200 and a larger diameter counter bore 206 through the forward portion of check valve 200 which forms an annular seating surface 208 in the valve member for receiving a ball 210. As will be understood by those skilled in the art, prior to when ball 210 is dropped into check valve 200 as shown in FIG. 4, fluid freely flows through hydrajetting sub 20 and check valve 200. After ball 210 is seated on annular seating surface 208 in check valve 200 as illustrated in FIG. 4, flow through check valve 200 is terminated, causing fluid passing into work string 12 and hydrajetting sub 20 to exit hydrajetting sub 20 via nozzles 22. When it is desired to reverse circulate fluids through check valve 200, hydrajetting sub 20 and work string 12, the fluid pressure exerted within work string 12 is reduced whereby higher pressure fluid surrounding hydrajetting sub 20 and check valve 200 flows through check valve 200, causing ball 210 to be pushed out of engagement with the annular seating surface 208, and through nozzles 22 into and through work string 12. As will be appreciated by one of ordinary skill in the art, check valve 200 is only one of a number of possible permutations of possible check valves for use in the present invention and the present invention is not limited to only the presently described check valve 200. Further, it is possible to replace check valves such as check valve 200 with a plug. In addition, as described above, in certain embodiments of the present invention where DPU 14 is located below hydrajetting sub 20, DPU 14 may act to prevent liquid from exiting inner fluid flow passageway 18 except through nozzles 22. In embodiments containing a plug in place of check valve 200, or when DPU 14 acts to prevent liquid from exiting inner fluid flow passageway's except through nozzles 22, all fluid entering work string 12 exits through nozzles 22. An optional pressure and/or temperature sensor, may be used to determine the pressure and temperature characteristics of the fluid exiting through check valve 200, such as through reduced diameter longitudinal bore 204.

Hydrajetting tool assembly 10 may in certain embodiments include packing device 300. Packing device 300 is any one of a number of packers known to those of skill in the art for sealing the wellbore. This seal is designed to isolate the portion of the formation to be fractured from portions below or beyond hydrajetting tool assembly 10. It is not expected that the seal formed by packing device 300 be complete, but it should be sufficient to allow fracturing of the desired formation. Typically, packing device 300 will seat against the sides of the wellbore or well casing to form this seal. Packing device 300 is typically located below hydrajetting sub 20.

Hydrajetting tool assembly 10 further includes directional sub 40. Directional sub 40 may include any number of devices suitable for determining both the inclination and azimuth angle of hydrajetting tool assembly 10. Suitable examples of directional sub 40 include, but are not limited to, gyroscopic surveyors, wireline steerers, memory pulsed neutron logging devices, and electromagnetic logging devices, all of which are familiar to those of ordinary skill in the art. Directional sub 40 is designed to communicate with surface equipment through such communications means as mud pulse, sonic, and wireline. Directional sub 40 may be powered by DPU 14 or, in the alternative, may be powered by an integrated power system, typically a device containing batteries. Alternatively, for instance, in embodiments where DPU 14 is absent, directional sub 40 may be powered from the surface through conducting material located within the wall of work string 12. Directional sub 40 is mechanically connected to hydrajetting sub 20. In some embodiments of the present invention, directional sub 40 is located such that other equipment, for example packing device 300, is mechanically located between directional sub 40 and hydrajetting sub 20. Such positioning may be desirable to lessen vibrational effects of hydrajetting sub 20 on sensitive electronic or mechanical components of directional sub 40.

Additional equipment that may be included in hydrajetting tool assembly 10 includes a hole finder, i.e., a device commonly used in drilling to find holes in piping such as liners or casing, gamma radiation source, a device used to determine, and a collar locator, i.e., a device designed to detect drill pipe collars. Typically, this additional equipment will be located contiguous with directional sub 40, although any appropriate location on hydrajetting tool assembly 10 may be used for such equipment.

Referring now to FIG. 5, a hydrocarbon producing formation 1150 is illustrated penetrated by wellbore 1100. Wellbore 1100 includes substantially vertical portion 404 which extends to the surface, and may include substantially horizontal portion 406 which extends into formation 1150. Work string 12 having the hydrajetting tool assembly 10 and an optional centralizer 408, a device designed to maintain hydrajetting tool assembly 10 at least some distance away from the sides of wellbore 1100 and preferably at or near the center of wellbore 1100, attached thereto is shown disposed in wellbore 1100. In certain situations, substantially horizontal portion 406 of wellbore 1100 may be lined with wellbore casing 410. Wellbore casing 410 may be used to stabilize wellbore 1100, prevent communication between different sections of formation 1150, and/or prevent seepage of hydrocarbon fluids into wellbore 1100 prior to a desired time.

Hydrajetting tool assembly 10 is positioned in wellbore 1100 adjacent to the portion of formation 1150 to be fractured. Packing device 300 is then set so that if forms a seal as described above in wellbore 1100. In one embodiment of the present invention wherein check valve 200 is used, a fluid is pumped through work string 12 and through hydrajetting tool assembly 10, whereby the fluid flows through the check valve 200 and circulates through wellbore 1100. The circulation is preferably continued for a period of time sufficient to clean debris, pipe dope and other materials from inside work string 12 and from wellbore 1100. Thereafter, ball 210 is dropped through work string 12, through hydrajetting sub 20 and into check valve 200 while continuously pumping fluid through work string 12 and hydrajetting tool assembly 10. When ball 210 seats on annular seating surface 208 in check valve 200, fluid is forced through nozzle 22 of hydrajetting sub 20. The rate of pumping the fluid into the work string 12 and through the hydrajetting sub 20 is increased to a level whereby the pressure of the fluid which is jetted through the nozzles 22 reaches a desired jetting pressure.

In sections of open hole wellbore 1100 having wellbore casing 410, it may be necessary to perforate wellbore casing 410 before forming microfractures, such as through the use of hydrajetting sub 20. Hydrajetting sub 20 may be used to make a number of different types of perforations in wellbore casing 410, commonly described as “cuts.” For instance, in certain formations, wellbore casing 410 may be perforated in only a single direction, e.g., towards the surface. In such a case, where nozzles 22 are oriented in one direction, fluid may be forced through nozzles 22 in that single direction. Generally, in such situations, directional sub 40 is used to determine the orientation of hydrajetting sub 20. Hydrajetting sub 20 may then be oriented through rotation, either by rotating sleeve 16 or from surface equipment, so that nozzles 22 point in the desired direction. Fluid may then be forced through nozzles 22 to make the single direction cut.

Where it is desirable to make multiple perforations at different circumferential locations about wellbore casing 410, after the initial perforation, fluid flow through nozzles 22 may be stopped, hydrajetting sub 20 may be rotated, as described above, to a different circumferential location, and fluid flow through nozzles 22 restarted. This process may be repeated as necessary to completely perforate wellbore casing 410. In other situations, it may be desirable to make a longitudinal cut of wellbore casing 410, called a “vertical cut” when the longitudinal cut is made in mostly substantially vertical portion 404. When a longitudinal cut is desired, hydrajetting tool assembly 10 is raised or lowered while fluid is jetted through nozzles 22. In addition, it certain situations it may be desirable to make a spiral cut of wellbore casing 410. Normally, a spiral cut is made when it is necessary to cut the wellbore casing 410 around its entire circumference, for instance, when the well is to be abandoned. In such a situation, fluid is jetted through nozzles 22 while hydrajetting sub 20 is rotated, either by use of rotating sleeve 16 or through the use of surface equipment.

Further, fluid jetted through nozzles 22 may be used to cause the creation of the cavities 50 and microfractures 52 in formation 1150 as illustrated in FIG. 6. FIG. 6 depicts a situation wherein the center of fracture point is centered on wellbore 1100. As described previously, where the center of fracture point is not centered on wellbore 1100, such fractures would be centered in an area outside wellbore 1100. Directional sub 40 is used to determine the orientation of hydrajetting sub 20 within wellbore 1100. Rotating sleeve 16 or surface equipment may then be used to orient hydrajetting sub 20 within wellbore 1100. A variety of fluids can be utilized in accordance with the present invention for forming fractures, including aqueous fluids, viscosified fluids, oil based fluids, and even certain “non-damaging” drilling fluids known in the art. Various additives can also be included in the fluids utilized such as abrasives, fracture propping agent, e.g., sand or artificial proppants, acid to dissolve formation materials and other additives known to those skilled in the art.

As will be described further hereinbelow, the jet differential pressure (P_(jd)) at which the fluid must be jetted from nozzles 22 to result in the formation of the cavities 50 and microfractures 52 in the formation 1150 is a pressure of approximately two times the pressure (P_(i)) required to initiate a fracture in the formation less the ambient pressure (P_(a)) in the wellbore adjacent to the formation i.e., P_(jd)≧2×(P_(I)−P_(a)). The pressure required to initiate a fracture in a particular formation is dependent upon the particular type of rock and/or other materials forming the formation and other factors known to those skilled in the art. Generally, after a wellbore is drilled into a formation, the fracture initiation pressure can be determined based on information gained during drilling and other known information. Since wellbores are often filled with drilling fluid and since many drilling fluids are undesired, the fluid could be circulated out, and replaced with desirable fluids that are compatible with the formation. The ambient pressure in the wellbore adjacent to the formation being fractured is the hydrostatic pressure exerted on the formation by the fluid in the wellbore or a higher pressure caused by fluid injection.

As mentioned above, propping agent may be combined with the fluid being jetted so that it is carried into the cavities 50 into fractures 60 connected to the cavities. The propping agent functions to prop open fractures 60 when they attempt to close as a result of the termination of the fracturing process. In order to insure that propping agent remains in the factures when they close, the jetting pressure is preferably slowly reduced to allow fractures 60 to close on propping agent which is held in the fractures by the fluid jetting during the closure process. In addition to propping the fractures open, the presence of the propping agent, e.g., sand, serves as an abrasive agent and in the fluid being jetted facilitates the cutting and erosion of the formation by the fluid jets. As indicated, additional abrasive material can be included in the fluid, as can one or more acids which react with and dissolve formation materials to enlarge the cavities and fractures as they are formed.

As further mentioned above, some or all of the microfractures produced in a subterranean formation can be extended into the formation by pumping a fluid into the wellbore to raise the ambient pressure therein. That is, in carrying out the methods of the present invention to form and extend a fracture in the present invention, hydrajetting sub 20 is positioned in wellbore 1100 adjacent the portion of formation 1150 to be fractured and fluid is jetted through the nozzles 22 against the formation 1150 at a jetting pressure sufficient to form the cavities 50 and the microfractures 52. Simultaneously with the hydrajetting of the formation, a fluid may be pumped into wellbore 1100 at a rate to raise the ambient pressure in wellbore 1100 adjacent formation 1150 to a level such that the cavities 50 and microfractures 52 are enlarged and extended whereby enlarged and extended fractures 60 are formed. As shown in FIG. 6, the enlarged and extended fractures 60 are preferably formed in spaced relationship along wellbore 1100 with groups of the cavities 50 and microfractures 52 formed therebetween.

Following the fracture of formation 1150, the annulus or wellbore may be “packed,” i.e., a packing material may be introduced into the fractured zone to reduce the amount of fine particulants such as sand from being produced during the production of hydrocarbons. The process of “packing” is well known in the art and typically involves packing the well adjacent the unconsolidated or loosely consolidated production interval, called gravel packing. In a typical gravel pack completion, a sand control screen is lowered into the wellbore on a workstring to a position proximate the desired production interval. As described above, this sand control screen may be included as a part of hydrajetting tool assembly 10, typically below packing device 300. A fluid slurry including a liquid carrier and a relatively coarse particulate material, which is typically sized and graded and which is referred to herein as gravel, is then pumped down the workstring and into the well annulus formed between the sand control screen and the perforated well casing or open hole production zone.

The liquid carrier either flows into the formation or returns to the surface by flowing through a wash pipe or both. In either case, the gravel is deposited around the sand control screen to form the gravel pack, which is highly permeable to the flow of hydrocarbon fluids but blocks the flow of the fine particulate materials carried in the hydrocarbon fluids. As such, gravel packs can successfully prevent the problems associated with the production of these particulate materials from the formation.

In another embodiment of the present invention, the proppant material, such as sand, is consolidated to better hold it within the microfractures. Consolidation may be accomplished by any number of conventional means, including, but not limited to, introducing a resin coated proppant (RCP) into the microfractures.

Another operation possible using at least one embodiment of the present invention is known to those of skill in the art as a cement squeeze. Following perforation or fracturing, evaluation of perforation or fracturing operation may be determined by the operator to be inadequate. In such a situation, the operator may wish to close the perforations or isolate formation 1150 from wellbore 1100. Following the perforation or fracturing operation, cement may be pumped down work string 12 and out nozzles 22 of hydrajetting sub 20. After setting, the cement acts to close the perforations of well casing 410 or isolate formation 1150 from wellbore 1100.

Therefore, the present invention is well-adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While the invention has been depicted, described, and is defined by reference to exemplary embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects. 

1. A method of fracturing a subterranean formation penetrated by a wellbore, comprising the steps of: (a) positioning a fracturing tool within the wellbore, wherein the fracturing tool has a fracturing tool outer wall; (b) initiating a fracture having a center of fracture point, wherein the center of fracture point is located within the subterranean formation but not within the wellbore; and (c) creating the fracture.
 2. The method of claim 1 wherein the wellbore comprises a substantially vertical section, and step (a) further comprises the step of positioning the fracturing tool within the substantially vertical portion of the wellbore.
 3. The method of claim 1 wherein the wellbore comprises a substantially horizontal section, and step (a) further comprises the step of positioning the fracturing tool within the substantially horizontal portion of the wellbore.
 4. The method of claim 1 wherein the fracturing tool comprises nozzles.
 5. The method of claim 4 wherein the nozzles are angled at an acute angle to the fracturing tool outer wall.
 6. The method of claim 5 wherein the center of fracture point is at an acute angle to the fracturing tool outer wall.
 7. The method of claim 1 wherein: the fracturing tool comprises a hydrajetting tool assembly mechanically connected to a work string; the work string comprises an outer wall and an inner wall; and the hydrajetting tool assembly comprises: a hydrajetting sub defined by an outer wall and an inner fluid flow passageway; a port formed through the outer wall of the hydrajetting sub and adapted to communicate with the inner fluid flow passageway; a nozzle mounted within the port; and a directional sub, wherein the directional sub is mechanically connected to the hydrajetting sub.
 8. A method of fracturing a subterranean formation penetrated by a wellbore, comprising the steps of: (a) positioning a hydrajetting tool assembly within the wellbore, wherein the hydrajetting tool assembly comprises: a hydrajetting sub defined by an outer wall and an inner fluid flow passageway; a port formed through the outer wall and adapted to communicate with the inner fluid flow passageway; a nozzle mounted within the port; and a directional sub, wherein the directional sub is mechanically connected to the hydrajetting sub; (b) initiating a fracture having a center of fracture point by introducing a fracturing fluid into the inner fluid flow passageway of the hydrajetting sub and jetting the fracturing fluid through the nozzle against the subterranean formation at a pressure sufficient to form cavities in the formation, wherein the center of fracture point is located within the subterranean formation but not within the wellbore, and the cavities in the subterranean formation are in fluid communication with the wellbore; and (c) creating the facture by maintaining the fracturing fluid in the cavities while jetting at a sufficient static pressure to fracture the subterranean formation.
 9. The method of claim 8 further comprising prior to step (b) the steps of: establishing a desired orientation of the hydrajetting tool assembly; determining the orientation of the hydrajetting tool assembly with the directional sub; and rotating the hydrajetting tool so that the orientation of hydrajetting tool assembly equals the desired orientation of the hydrajetting tool assembly.
 10. The method of claim 8 wherein the hydrajetting tool assembly further comprises a packer, and the method further comprises the step of forming a seal to prevent fluid flow downstream of the seal and to permit the flow of the fracturing fluid into the subterranean formation.
 11. The method of claim 10 wherein the step of forming the seal comprises the steps of: connecting the packer to the hydrajetting tool assembly; and setting the packer.
 12. The method of claim 8 further comprising the steps of: adding a propping agent to the fracturing fluid; and propelling the propping agent into the cavities.
 13. The method of claim 8 further comprising the step of adding a consolidation agent to the fracturing fluid.
 14. The method of claim 8 wherein the consolidation agent is a resin coated proppant.
 15. The method of claim 8 further comprising following step (c) the step of packing the wellbore by introducing a fluid slurry into wellbore.
 16. The method of claim 15 wherein the fluid slurry comprises gravel.
 17. A hydrajetting tool assembly comprising: a hydrajetting sub defined by an outer wall and an inner fluid flow passageway; a port formed through the outer wall and adapted to communicate with the inner fluid flow passageway; a nozzle mounted within the port; and a directional tool, wherein the directional tool is mechanically connected to the hydrajetting sub.
 18. The hydrajetting tool assembly of claim 17 wherein the nozzle is comprised of tungsten carbide or ceramic.
 19. The hydrajetting tool assembly of claim 17 wherein the nozzle extends beyond the outer wall and is oriented at an angle between about 30 degrees and about 90 degrees relative to the outer wall.
 20. The hydrajetting tool assembly of claim 19 wherein the nozzle is oriented at an angle between about 45 degrees and about 90 degrees relative to the outer wall.
 21. The hydrajetting tool assembly of claim 17 wherein the port is approximately circular.
 22. The hydrajetting tool assembly of claim 17 wherein: the hydrajetting tool assembly is mechanically connected to a work string; the work string comprises: an outer wall; an inner wall; a non-conducting material; and a conducting material between the work string outer wall and the work string inner wall; and the hydrajetting tool assembly is capable of communicating with surface equipment through the conducting material
 23. The hydrajetting tool assembly of claim 17 further comprising a mud pulse or sonic generator connected to the hydrajetting sub.
 24. The hydrajetting tool assembly of claim 17 further comprising a plurality of ports and a plurality of nozzles, wherein the nozzles are mounted within the ports.
 25. The hydrajetting tool assembly of claim 24 wherein the nozzles are oriented in an approximately unitary direction.
 26. The hydrajetting tool assembly of claim 24 wherein the nozzles are located in two rows arranged longitudinally along the hydrajetting sub, and the rows are located 180° apart.
 27. The hydrajetting tool assembly of claim 17 further comprising a downhole power unit mechanically connected to the hydrajetting sub.
 28. The hydrajetting tool assembly of claim 27 wherein the downhole power unit comprises a battery, fuel cell, or fluid motor and generator.
 29. The hydrajetting tool assembly of claim 17 further comprising a rotating sleeve mechanically connected to the hydrajetting sub.
 30. The hydrajetting tool assembly of claim 29 further comprising a downhole power unit mechanically connected to the rotating sleeve.
 31. The hydrajetting tool assembly of claim 30 wherein the hydrajetting sub is directly connected to rotating sleeve, and the rotating sleeve is directly connected to the downhole power unit.
 32. The hydrajetting tool assembly of claim 17 further comprising a check valve mechanically connected to the hydrajetting sub.
 33. The hydrajetting tool assembly of claim 32 further comprising a temperature sensor.
 34. The hydrajetting tool assembly of claim 32 further comprising a pressure sensor.
 35. The hydrajetting tool assembly of claim 17 further comprising a packing device mechanically connected to the hydrajetting sub, wherein the packing device is capable of seating against the wellbore to form a seal.
 36. The hydrajetting tool assembly of claim 17 wherein the directional tool comprises a gyroscopic surveyor, a wireline steerer, a memory pulsed neutron logging device, or an electromagnetic logging device.
 37. The hydrajetting tool assembly of claim 36 wherein the directional tool is capable of communicating with surface equipment.
 38. The hydrajetting tool assembly of claim 36 wherein the directional tool further comprises an integrated power system.
 39. The hydrajetting tool assembly of claim 17 further comprising a hole finder mechanically connected to the hydrajetting tool.
 40. The hydrajetting tool assembly of claim 17 further comprising a gamma radiation source mechanically connected to the hydrajetting sub.
 41. The hydrajetting tool assembly of claim 17 further comprising a collar locator mechanically connected to the hydrajetting sub. 